Wellbore directional steering tool

ABSTRACT

An apparatus for selectively controlling the direction of a well bore comprising a mandrel rotatable about a rotation axis; a direction controller means comprising at least two parts configured to apply a force to said mandrel with a component perpendicular to the said rotation axis; a housing having an eccentric longitudinal bore forming a weighted side and being configured to freely rotate under gravity; and a driver for selectively varying the angle of the force relative to the weighted side of the housing about said rotation axis, the driver being configured to move the two parts independently of one another.

FIELD OF INVENTION

[0001] The present invention relates to the field of oil and gasdrilling. More specifically the present invention relates to anapparatus and method for selecting or controlling, from the surface, thedirection in which a wellbore proceeds.

[0002] A drill operator often wishes to deviate a wellbore or controlits direction to a given point within a producing formation. Thisoperation is known as directional drilling. One example of his is for awater injection well in an oil field which is generally positioned atthe edges of the field and at a low point in that field (or formation).

[0003] In addition to controlling the required drilling direction, theformation through which a wellbore is drilled exerts a variable force onthe drill string at all times. This along with the particularconfiguration of the drill can cause the drill bit to wander up, down,right or left. The industrial term given to this effect is “bit-walk ”and many methods to control or redirect “bit-walk” have been tried inthe industry. The effect of bit walk in a vertical hole can becontrolled, by varying the torque and weight on the bit while drilling avertical hole, However, in a highly inclined or horizontal well,bit-walk becomes a major problem.

BACKGROUND OF THE INVENTION

[0004] At present, in a order to deviate a hole left or right, thedriller can choose from a series of special downhole tools such asdownhole motors, so-called “bent subs” and more recently a steerablemotors.

[0005] A bent sub is a short tubular that has a slight bend to one side,is attached to the drill string, followed by a survey instrument, ofwhich an MWD tool (Measurement While Drilling which passes wellboredirectional information to the surface) is one generic type, followed bya downhole motor attached to the drill bit The drill sting is loweredinto the wellbore and rotated until the MWD tool indicates that theleading edge of the drill bit is facing in the desired direction Weightis applied to the bit through the drill collars and, by pumping drillingfluid through the drill string, the downhole motor rotates the bit

[0006] U.S. Pat. No. 3,561,549 relates to a device which givessufficient control to deviate and star an inclined hole form or controlbit-walk in a vertical wellbore. The drilling tool has a non-rotatingsleeve with a plurality of fins (or wedges) on one side is placedimmediately below a downhole motor in turn attached to a bit

[0007] U.S. Pat. No. 4,220,213 relates to a device which comprises aweighted mandrel. The tool is designed to take advantage of gravitybecause the heavy side of the mandrel will seek the low-side of thehole. The low side of the wellbore being the side furthest away from thevertical.

[0008] U.S. Pat. No. 4,638,873 relates to a tool which has aspring-loaded shoe and a weighted heavy side which can accommodate agauge insert held in place by a retaining bolt

[0009] U.S. Pat. No. 5,220,963 discloses an apparatus having an innerrotating mandrel housed in three non-rotating elements.

[0010] Thus, it is know how to correct a bit-walk in a wellbore.However, if changes in the forces that cause bit-walk occur whiledrilling, all the prior art tools must be withdrawn in order to correctthe direction of the wellbore. The absolute requirement for toolwithdrawal means that a round trip must be performed. This results in acompromise of safety and a large expenditure of time and money.

[0011] The applicant's own previous patent application WO 96/31679 andU.S. Pat. No. 5,979,570 partially addresses the problem of bit-walk inan inclined wellbore. The device described in this patent applicationand patent comprises eccentrically bored inner and outer sleeves. Theouter sleeve being freely moveable so that it can seek the low side ofthe wellbore, the weighted side of the inner eccentric sleeve beingcapable of being positioned either on the right side or the left side ofthe weighted portion of the outer eccentric sleeve to correct in abinary manner for bit walk

[0012] The applicant has now developed an improved downhole tool whichcan correct for bit walk in a highly inclined wellbore and which iscapable of controlling both the inclination and the Azimuthal plane ofthe well bore.

SUMMARY OF THE INVENTION

[0013] In a first aspect, We present invention provides an apparatus forselectively controlling the direction of a well bore, the apparatuscomprising:

[0014] a mandrel rotatable about a rotation axis; a direction controllermeans comprising at least two members spaced apart along said mandreland configured to apply a force to said mandrel with a componentperpendicular to the said rotation axis;

[0015] a housing having an eccentric longitudinal bore forming aweighted side and being configured to freely rotate under gravity; and

[0016] a driver for selectively varying the angle of the force relativeto the weighted side of the housing about said rotation axis, the driverbeing capable of moving the two parts independently of one another.

[0017] The provision of a two part direction controller allows morecontrol over the drilling direction in order to drill in a requireddirection and to compensate for bit-walk. Further, the provision of atwo part direction controller allows a null or a zero force to beapplied to the mandrel by precessing the direction controller about themandrel.

[0018] The two parts of the direction controller can be configured in anumber of different ways. Preferably, the two parts are located ondifferent sides of the central plane. A particularly preferablearrangement is achieved when both of the two parts are capable ofapplying a independent force to the mandrel. For example, the two partsmay be located on either side of the central plane of the housing. Forexample, both parts may comprise eccentrically bored sleeves.

[0019] In an alternative configuration, only one part is capable ofapplying a radial force to the mandrel, the other part only beingcapable of applying a symmetric force about the mandrel. For example,one part may be an eccentrically bored sleeve and the other may be aconcentrically bored sleeve. If the arrangement is envisaged where aconcentrically bored sleeve is located on one side of the central planeand an eccentrically bored sleeve is located on the other, then it ispossible to form a so-called “point the bit” arrangement. Theeccentrically bored sleeve may be located either above or below thecentral plane of the housing. Two eccentrically bored sleeves orientedat 180° to each other about the mandrel can also achieve this effect

[0020] References have been made to the at least one part beingeccentrically bored. However, it should be noted that the same effectcan be achieved with a sleeve which is spatially symmetric about therotation axis, but which has a denser material or a weight located atone side of the sleeve.

[0021] Further there is no requirement for the direction controller tobe a sleeve. A cam or even a linear actuator could be used to the sameeffect as an eccentric sleeve.

[0022] The driver is configured to move the two parts of the directioncontrol means independent of one another. This is applicable regardlessof the nature of the direction controller for example if the directioncontrol means comprises a sleeve, cam, linear actuator or anothercomponent which can achieve the same result.

[0023] Where the direction controller comprises a linear actuator, theactuator may be mounted such that that can move about the circumferenceof said mandrel to apply a force to the mandrel at the requiredposition. Preferably, a plurality of linear actuators are placed aroundthe circumference of the mandrel. More preferably, at least threeactuators are used at equal angles in a plane about said mandrel. Thethree actuators being capable of applying a force to the mandrel in anydirection in a plane about its axis.

[0024] Therefore, in a second aspect, the present invention provides anapparatus for selectively controlling the direction of a wellbore, theapparatus comprising: a mandrel which is rotatable about a rotationaxis;

[0025] a direction controller comprising at least one linear actuatorconfigured to apply a force to said mandrel;

[0026] a housing having an eccentric longitudinal bore and beingconfigured to freely rotate under gravity; and a drive means forselectively varying the angle of the force relative to the weighted sideof the housing about said rotation axis.

[0027] Preferably, the driver in accordance with either the first or thesecond aspects of the present invention is configured to change thedirection of the force within a tolerance of at most 10°, morepreferably at most 5°, even more preferably at most 1°.

[0028] A possible configuration of the driver and the directioncontroller can be achieved by drive wheel and track arrangement.

[0029] The track and drive wheel preferably comprise a plurality ofinterengaging teeth to effect movement therebetween. Such an arrangementis commonly referred to as a pinion and drive wheel arrangement. Thisarrangement is particularly preferable as, when stationary, the drivewheel locks against the track serving to secure the inner sleeve inposition relative to the housing. The track and drive wheel arrangementcould also be provided by a drive wheel with a circumference which has ahigh coefficient of friction with the said track.

[0030] The said drive wheel may be located on a part of the directioncontroller and the housing may be provided with a track on its internalsurface, such that movement of the drive wheel causes movement of thesaid part of the direction controller with respect to the housing.Alternatively, the drive wheel may be located in the outer housing and apart of the direction controller may be provided with a track such thatmovement of the drive wheel affects relative movement between the saidpart of the direction controller and the housing. This arrangement ispreferable as it allows a power source to drive the drive wheel to belocated within the housing.

[0031] The above drive means have been described with relation to themovement of a single part of the direction controller. However, a singledrive wheel could be used to move the two parts of the direction controlmeans. Two such drive means may be used to drive the two parts of thedirection controller respectively.

[0032] The driver may comprise a hydraulic or electric motor or thelike. Further, drive means may be battery powered or powered by therotation of the rotating mandrel.

[0033] In operation, the driver is required to move the direction of theforce with respect to the outer housing. Typically, some means arerequired to instruct the driver to move the position of the direction ofapplication of the force on the mandrel.

[0034] Therefore, the apparatus preferably fiddler comprises logic meansfor determining when the direction of the force applied by the directioncontroller should be moved. The logic means may be located in thedownhole assembly, or they may be located at the surface with means forcommunicating with the downhole assembly. If the logic means are locatedwithin the downhole assembly they may be configured to send and/orreceive information from the surface in order to determine when thedirection of the force should be moved.

[0035] If the logic means are located at the downhole assembly and areconfigured to receive information from the surface, preferablyinformation is sent to the logic means using one of the parameters whichare readily available during drilling. For example, the weight on thedrill bit and pump cycling.

[0036] The logic means may comprise a sensor for sensing a wellborefluid pulses and decoding said pulses to determine when the direction ofthe force should be changed. A series of fluid pulses can be sent downsaid drill string. The drill string pulses can be used to encode data tosend to the downhole assembly.

[0037] The fluid pressure could also be used to determine the positionof the force of the direction controller. For example, fluid passagewayscould be provided which extend generally radially through said mandrel,said direction controller and said housing such that, when saiddirection controller, which may for example, be a sleeve, cam etc., isin a first position, said series of drilling fluid passageways alignwith each other so as to allow drilling fluid to flow readily from saidinterior of the said mandrel to said exterior of said housingaccompanied by a relatively low pressure drop, and when said sleeve isnot in the first position, said drilling fluid passageways are inmisalignment so as to restrict drilling fluid flow from said interior ofsaid mandrel to said exterior of said housing accompanied by relativelyhigh pressure drop. This allows the position of the direction controlmeans to be determined.

[0038] In a preferred arrangement, the above is achieved by theprovision of a bit-jet and orifice combination positioned within saidgenerally radial passageway in said mandrel adjacent said directioncontrol means.

[0039] Further, the logic means may comprise a detector for detectingthe rotating of the drill string. The drill string rotation could bedetected by using magnetic fields for example in the manner described inGB 2 356 207. The logic means may be configured to detect the frequencyof rotation of the drill string. This allows a magnitude of a scalarparameter such as an angle through which to move the force applied bythe direction control means. The logic means may be configured todetermine a time period between rotation and non-rotation of the drillstring wherein said time period determines when the angle of said forceshould be changed with respect to the weighted side of said housing orthe radial position of the housing.

[0040] The logic means and the driver may be stored within the housing.Alternatively, the logic means may be located within a tubular housingconnected to at least one of the mandrels, direction controller andhousing. The apparatus may further comprise an energy source forsupplying power to the driver and/or logic means,

[0041] Preferably, the rotating mandrel is terminated at both ends inthe appropriate standard tool joint used in the drilling industry forready attachment to sub the bit, other downhole tools, or drill pipe.

[0042] The rotating mandrel is used to transfer the rotary motion of thedrill pipe to the drill bit and acts as continuation conduit of thedrill pipe for all drilling fluids passing down the drill pipe and ontothe drill bit

[0043] The above description has primarily considered sendinginformation from the surface to the downhole assembly in order to changethe position of the force on the mandrel. However, during drilling, thedownhole assembly is actually located within the wellbore, therefore thedownhole assembly itself is a far better position to determine dataconcerning the strata then any surface based analysis equipment.

[0044] Therefore, preferably, the downhole assembly is provided with asensor for sensing geological information about the formation beingdrilled.

[0045] Therefore, in a third aspect, the present invention provides anapparatus for selectively controlling the direction of a well borecomprising a mandrel rotatable about a rotation axis; a directioncontrol means comprising configured to apply a force to said mandrelwith a component perpendicular to the said rotation axis; a housinghaving an eccentric longitudinal bore forming a weighted side and beingconfigured to freely rotate under gravity; a drive means for selectivelyvarying the angle of the direction of force about said rotation axis;and sensing means for sensing information about the formation which isbeing drilled.

[0046] The sensing means preferably comprises a sensor and analysingmeans for analysing data collected by the sensor. If the analysis isperformed by the downhole assembly, then there is no time wasted insending the data to the surface. Another stage further would be to allowthe tool to control itself on the basis of the data sensed by itssensors.

[0047] In a fourth aspect, the present invention provides an apparatusfor drilling a well bore, the apparatus comprising a drilling memberconfigured to drill in a predetermined drilling direction; directioncontrol means for controlling the drilling direction of said drillingmember; a sensor for determining at least a characteristic of the stratabeing drilled; wherein said direction control means determines thedrilling direction based on the data collected by said sensor.

[0048] Preferably, the sensor is configured to detect gamma rays.

[0049] The apparatus may further comprise a plurality of stabilisershoes. These stabiliser shoes may be circumferentially offset by apredetermined amount in relation to the weight of the housing. Morepreferably, the apparatus comprises two stabiliser shoes. The stabilisershoes which may be blades, wedges etc. extend radially outward andlaterally along the circumference on either side of the outer eccentricsleeve.

BRIEF DESCRIPTION OF THE DRAWINGS

[0050] The present invention will now be described with reference to thefollowing preferred non-limiting embodiments in which;

[0051]FIG. 1 shows an elementary cutaway side elevational view of anapparatus according to an embodiment of the invention in a slightlyinclined wellbore having its low-side on the left;

[0052]FIG. 2 is an elementary side elevational view of the tool of FIG.1, having a weighted side on the left and illustrating the position ofthe stabilizer shoes;

[0053]FIG. 3 is an elementary side elevational view of the tool of FIG.1, rotated through ninety-degrees;

[0054]FIG. 4 is an elementary cross section of the tool of FIGS. 2 and 3taken at A-A in FIG. 2 and 3;

[0055]FIG. 5A is an elementary top view of the tool of FIG. 1 employedin a wellbore illustrating its use in making a right-turn; FIG. 5B is anelementary top view of the tool of FIG. 1 employed in a wellboreillustrating its use in correcting right-hand bit-walk or,alternatively, illustrating its use in making a left-hand

[0056]FIG. 6 is a tool according to another embodiment of the presentinvention;

[0057]FIG. 7A illustrates a drive coupled to the inner mandrel poweredby a motor means;

[0058]FIG. 7B illustrates a drive coupled to the outer housing poweredby a motor means;

[0059]FIG. 8 is an elementary cross section illustrating the fluidpressure inner eccentric sleeve position signaling means;

[0060]FIG. 9 is an elementary cross section of the device, showing thesignaling means, taken at A-A in FIG. 8; and

[0061]FIG. 10 is an elementary cross section of the device illustratinga signaling means using magnetic fields.

[0062]FIG. 11 is a Bottom Hole Assembly, including a tool according tothe invention, bit, MWD tool, drill collars, etc. used for left/rightborehole correction only;

[0063]FIG. 12A is the diagrammatic illustration for the suggested BottomHole Assembly of FIG. 11 showing the device, bit and stabilizers usedfor left/right borehole correction only;,

[0064]FIG. 12B is a suggested diagrammatic Bottom Hole Assembly,including the device, bit and stabilizers used for up/down boreholecorrection only;

[0065]FIG. 12C is a suggested diagrammatic Bottom Hole Assembly used forup/down and left/right correction;

[0066]FIG. 13 is an elementary cross section of a device in accordancewith a preferred embodiment where the direction controller comprises aplurality of linear actuators; and

[0067]FIG. 14 is a schematic of a device according to a preferredembodiment of the invention and comprising a sensor.

DETAILED DESCRIPTION OF THE INVENTION

[0068] Before the device is described, the phenomena of “bit walks willbe discussed in more detail.

[0069] The formation through which a wellbore is drilled exerts avariable force on the drill sting at all times. This variable force isessentially due to the clockwise rotary motion of the bit, the weightapplied to the drill bit and the sty of the formation. Formation is ageneral term used to define the material—namely rock, sand, shale, clay,etc.—that the wellbore will pass through in order to open a pathway orconduit to a producing formation, This variable force will result in avariable change in the direction of the wellbore.

[0070] The formation is generally layered by the action of nature overmillions of years and is not necessarily level. The formation will havedips, defined as a change in direction of the layers of the formation,which can end either upward or downward. As the drill bit moves into adip or from one type of formation to another, the force on the drill bitwill change and cause the drill bit to wander up, down, right or leftThis wander is the natural result of the reaction of the formation tothe clockwise torque and forward drilling force exerted by the drill biton the formation. Mathematically the result can be viewed as a simplevector cross product between the torque force and the drilling force orweight on bit. The cross product results in a component force towardsthe right of the drilling force. The industrial term given to thiseffect is bit-walk” and many methods to control or re-direct “bit-walk”have been tried in the industry.

[0071] Bit-walk is predictable, but the magnitude and, frequently, thedirection of bit-walk are generally unpredictable. Looking at the vectorcross product model, it can be seen that as the drilling force or weighton bit is varied, the cross product varies. Or, as the RPM of the drillstring is varied, the cross product varies. Or, as the formationchanges, the cross product changes, In drilling a wellbore, all of theseforces constantly vary; thus, the magnitude of bit-walk constantlychanges. The industry has learnt to control the effects of bit-walk in avertical hole by varying the torque and weight on bit while drilling avertical hole. However, in an inclined (non-vertical) hole bit-walk ismore problematic.

[0072] By industry definition, once an inclined hole is established, theside of the wellbore nearest to true horizontal is called the “Iow-side”of the hole. The opposite side of We hole is referred to as “high-side,”and is used as a reference point throughout the wellbore drillingoperation. The drilling force follows the longitudinal extension of thewellbore; thus, the drilling force is parallel to and spaced from thelow-side of the hole. Since bit-walk is the result of applied torque anddrilling force, then it can be anticipated that normal bit-walk will beto the right of the low-side of the hole. This definition applies in allwellbores.

[0073] In a vertical hole or slightly inclined hole, bit-walk may becontrolled by developing as much rigidity as possible in the lowerportion of the drill string near to the drill bit This can be andgenerally is accomplished by using drill string components of highrigidity and weight (drill collars or heavy-weight drill pipe) andstabilizer& A stabilizer, well known in the industry, is a tubularmember with a combination of radial blades or wedges (generally referredto as stabilizer shoes or blades), often having a helical configuration,circumferentially arranged around the tubular and extending beyond theouter diameter of the tubular. The extension of the stabilizer blades islimited to the diameter of the drill bit Thus, the stabilizer will workin a stable hole. However, if the wellbore washes out (increases indiameter due to formation or other downhole mechanical or hydrauliceffects) or where the lateral force exerted by the blades is less an thetorque effect of the drill bit, then the stabilizer loses itseffectiveness and bit-walk will occur. Thus, in a highly inclined orhorizontal well, bit-walk becomes a major problem.

[0074] Very often the driller wishes to deviate the wellbore or controlits direction to a given point within a producing formation. Thisoperation is known as directional drilling. For example, a waterinjection well in an oil field is generally positioned at the edges ofthe field and at a low point in that field (or formation). A verticalwellbore will be established and the wellbore “kicked-off” from verticalso that an inclined (or even horizontal) wellbore results. It is nownecessary to selectively guide the drill bit and s to the required pointin the relevant formation. In order to achieve this objective, controlof the wellbore is required in both the vertical plane (i.e. up anddown) and in the horizontal plane (i.e., left and right).

[0075]FIG. 1 is a side elevational shows a cutaway view of a downholedevice, 10. The device is shown in an inclined wellbore. FIG. 1amplifies the low-side 2 a of the hole 2, which the industry defines asMe side of the hole nearest the center of the earth. The low-side of thehole, 2 a, is on the left-hand side of the overall wellbore, 2,

[0076] The device 10 is shown attached to an upper adapter sub, 4, whichwould in turn be attached to a drill string (not shown). The adapter subis located at the upper end of the device 10, i.e. the end of the device10 which is closest to the opening of wellbore 2. The adapter sub isattached to an inner rotatable mandrel, 11. For the purposes of hisdescription, the relative terns upper and lower are defined with respectto the wellbore, the upper end of the wellbore being the open end, thelower end being the drilling face.

[0077] The adapter sub serves to connect the drill string to the innerrotatable mandrel 11. However, the adapter sub 4 may not be necessary ifthe drill string pipe threads match the device 10 threads.

[0078] The mandrel 11 has an elongate central part 11 a which extendsalmost the whole length of the tool 10, At either end, the central partof the mandrel 11 a is connected to an upper mandrel section 11 b and alower mandrel section 11 c.

[0079] The upper part 11 b of the mandrel 11 is attached to upperadapter sub 4.

[0080] The lower part 11 c of the inner rotating mandrel, 11, isattached directly to a drill bit, 7. In practice a lower adapter sub maybe located between the mandrel and drill bit 7 if the threads differbetween the mandrel 11 and drill bit 7.

[0081] An inner eccentric sleeve 12 is located about at least a part ofsaid mandrel. The mandrel 4 is free to rotate within the inner eccentricsleeve, 12. In practice, bearing surfaces will be present between theinner rotating mandrel, 11, and the inner eccentric sleeve, 12 to allowrotation of the mandrel 11. The mandrel, 11, must be capable of shedrotation within the inner sleeve, 12. The bearing surfaces will bediscussed in more detail later in the description.

[0082] The inner sleeve 12 of the example has two parts, an upper part12 a and a lower part 12 b. In the device 10 of FIG. 1, both the upperpart 12 a and the lower part 12 b have an eccentric bore for receivingthe mandrel 11. The upper part 12 a is located close to the top end ofthe device 10 and the lower part 12 is located towards the lower part ofthe device 10. The upper and lower parts of the inner sleeve are spacedapart from one another along the length of the mandrel 11.

[0083] An essentially tubular housing, which will be referred to asouter housing 13 completes the device 10 as shown in the Example ofFIG. 1. In the example of FIG. 1, the outer housing 13 houses the middlepart 11 a of the mandrel 11. The upper 12 a and lower 12 b parts of theinner sleeve are located at the upper and lower ends of the housing 13respectively, such that the housing 13 only covers a portion of each ofthe upper and lower parts of the inner sleeve 12 a, 12 b.

[0084] The inner eccentric sleeve, 12, may be turned freely within anarc, by a drive means (not shown), inside an outer eccentric housing ormandrel, 13. The bearing surface between the inner and outer mandrelsare not critical as Hey are not in constant mutual rotation. However,they must be capable of remaining clean in the drilling environmentScaled bearing stems would be appropriate.

[0085] The outer housing is eccentric on its outside. This heavier sideof the housing 13 is referred to as the “pregnant portion”, 20.

[0086] The pregnant portion 20, of the outer housing forms the heavyside of the outer housing and is manufactured as a part of the outersleeve. The outer housing 13 is freely rotatable under gravity such thatthe pregnant portion 20, will always seek the low side of the wellbore.In operation, the position of the inner sleeves is set with respect tothe position of the pregnant portion 20 of the outer housing. Therefore,the inner sleeve 11 is moveable with respect to the outer housing,

[0087]FIGS. 2 and 3 are external views of the device 10. The device isshown without upper adapter sub 4 or drill bit 7. The upper and lowerparts 11 b and 11 c of the mandrel are respectively located at the topand bottom of the device 10. Adjacent the upper and lower parts 11 b and11 c of the mandrel 11 are located the upper and lower parts 12 a and 12b of the inner sleeve. Viewed from the outside, the outer housing 13 islocated between the upper 12 a and lower 12 b parts of the inner sleeve.As explained with reference to FIG. 1, the upper and lower parts of theinner sleeve 12 are partially located within the housing 13. Theposition of the pregnant portion 20 of housing 13 is shown in outline.

[0088] Stabiliser shoes 21 are located on the outside of housing 13. Inthis particular example, three stabiliser shoes are located around thecircumference of the housing 13. The shoes are elongate and are alignedparallel with the rotation axis of the device 10. The shoes 21 arepositioned at 90° intervals from one another. As there are only threeshoes, they do not extend around the whole circumference of the outerhousing. The shoes 21 are arranged so tat there is a first shoe 180°away from the weighted portion, with two shoes positioned on either sideof the first shoe. The shoes 21 serve to counter any reactionaryrotation on the part of the outer housing caused by bearing frictionbetween the rotating mandrel, 11, and the inner eccentric sleeve, 12 andto center the housing 13, within the borehole 2.

[0089] The stabilizer shoes are normally removable and are sized to meetthe wellbore diameter. In fact, the same techniques used to size astandard stabilizer would be applied in choosing the size of thestabilizer shoes. Alternatively, the shoes, 21, could be formedintegrally with the outer housing, 13.

[0090] Other designs which incorporate anti-rotation features may alsoused For example, at least a part of the outer surface of the housingmay be provided with tooth like projections which are capable ofengaging with the side of the well-bore. Clutch mechanisms may also beemployed in order to stabilise the outer housing.

[0091]FIG. 3 shows the device of FIG. 2 rotated through 90°. Threesecondary shoes 14 are located around the lower part 11 c of mandrel 11.These stabiliser shoes 14 are arranged symmetrically around thecircumference of the mandrel with 120° between each shoe 14.

[0092]FIGS. 2 and 3 show the principle axis of wellbore 2 as C/L_(w) andthe rotation axis of the bit (or drill string) as C/L_(D). The rotationaxis of the drill string and the principle axis of the wellbore will notalways be parallel to one another. For example, when the directioncontrol means effects a change in the desired drilling direction. Therotation axis and the principle axis are offset by the eccentricity ofthe inner sleeve in FIG. 3 and are co-located in the views of FIGS. 2and 4.

[0093] When the tool is viewed through the axis which passes through thepregnant housing, the longitudinal axes are offset; on the other hand,when viewed through the axis which passes through the two stabilizershoes. 21, the two longitudinal axes are co-located.

[0094] Previously, the requirement of bearing surfaces between the innersurface of the inner sleeve and the outer surface of the rowing mandrelwas mentioned.

[0095] The bearings between the inner rotatable mandrel and the innereccentric sleeve pose a number of interesting problems. If the tool isused in conventional drilling, the inner mandrel must be capable ofturning at speeds of up to 250 RPM within the inner eccentric sleeve. Ifthe tool is used with downhole motors, the bearing speed will depend onthe position of the downhole motor with respect to the tool, but may besubstantially higher than the 250 RPM used in normal drilling. Thedownhole motor may be placed at either end of the tool. If the motor isplaced next to the bit, then the rotational bearing speed will be zero.If the tool is placed between the downhole motor and the bit, therotational speed will be the same as that of the output shaft of thedownhole motor. This speed can be higher than 250 RPM, which is normallyregarded as the maximum RPM encountered in conventional rotary drilling.

[0096] The inner mandrel to inner sleeve high speed bearings must belubricated, and the lubricating fluid will be the drilling fluid thatcirculates throughout the system. This means that the bearing must becapable of operating with some solids, having a potentially abrasivenature, present in the stream. Bearing of this nature are wellunderstood in the industry and will cause little problem. The thrustbearing, between the two elements, see location 28 on FIG. 9, must beexpected to show wear and is designed so that it can be replaced atreasonable service intervals without recourse to sophisticated servicefacilities. Basically the thrust bearing surface is a sacrificialbearing and plans should be made to replace this bearing with eachchange of bit. (At least the bearing should be examined each time thetool comes to the surface.) Means can also be provided to measure thebearing wear at the surface without loss of time.

[0097] The rotation between the outer housing, 13, and the innereccentric sleeve, 12, is controlled from the surface and is an ‘ondemand’ occurrence. Thus, these bearing surfaces need not take highcontinuous rotation speeds and standard sealed bearings may be used

[0098]FIG. 4 shows a cross section of the tool 10 through line A-A′ ofFIG. 3. In FIG. 4, the pregnant portion 20 of the outer housing 13locates itself at the low side of the wellbore 2. The stabiliser shoes21 located on the circumference of the outer housing are arranged suchthat the middle shoe is located against the high side of the wellbore 2with the other two shoes located on the right and left sides of thewellbore 2. The inner sleeve 12 is located within the bore of thehousing 13. Previously, the inner sleeve 12 has been described in termsof two parts, an upper 12 a and a lower part 12 b. FIG. 4 just shows theupper part 12 a of the sleeve. However, it will be appreciated by thoseskilled in the art that the lower part 12 b of the sleeve 12 could alsobe used in this cross section. The inner sleeve 12 is eccentricallybored. The mandrel 11, or more correctly, the central part of themandrel 11 a is located within the bore of the inner sleeve 12. Theinner sleeve 12 can be rotated with respect to the pregnant part 20 ofthe outer housing 13 thus changing the force on the mandrel 11.

[0099]FIG. 4A shows a cross section through line B-B′ of FIG. 3. In thispart of the tool, there is no outer housing 13 or inner sleeve 12. Thefigure just shows the mandrel 11, with its concentric bore. Threesecondary stabiliser shoes 14 are located symmetrically about themandrel 11.

[0100] The operation of the device will now be described with referenceto FIGS. 5A and 5B. FIGS. 5A and 5B show external views of the tool 10similar to that shown in FIGS. 2 and 3. Therefore, to avoid unnecessaryrepetition, like reference numerals will be used to denote likefeatures. The description of such features will not be repeated. A drillbit 7 is located on the lower end of the tool 10 in the manner describedwith reference to FIG. 1. Further, an adapter sub 4 is located to theupper part of the mandrel 11 as also described with reference to FIG. 1.

[0101] Both FIGS. 5A and 5B show a “top view” of the device, i.e. thedevice 10 is viewed from the high side of the wellbore and the pregnantportion 20 is located on the lower side of the wellbore underneath thedevice 10. In FIG. 5A, the upper and lower sleeve 12 offset is set tothe far right of the wellbore. This means that the thicker side of theinner sleeve 12 is located towards the right hand side of the wellbore.This causes the outer housing to exert pressure against the right handside of the wellbore 2. The fulcrum effect against the right side of thewellbore creates a force against the right hand side of the rotatingmandrel which forces the drill bit which is attached thereto to create ahole with a left hand bias.

[0102] The inner sleeve 12 has an upper portion 12 a and a lower portion12 b. In this specific example, both portions are moved together. Bothportions are drawn with an inclined line which shows the position of theheavy side of the inner sleeve 12. This line is a result of the internalcam form of the inner sleeve. The cam, of necessity has a wider side anda narrower side.

[0103] For the sake of clarification, whenever the radial placement ofthe wider part of the cam is in a certain attitude with respect to theborehole, forces generated by the cam section will deviate the boreholein a vector at 180 degrees to the position of the wider section.

[0104] The widest part of the cam which is closest to the outer housing13 (as drawn) defines the position of the bias of the inner sleeve.

[0105]FIG. 5B shows the reverse situation to FIG. 5A. Here, the widerbias portion of the inner sleeve is directed towards the left hand wallof the wellbore 2. This causes the outer housing 13 to exert pressureagainst the left hand side of the wellbore. Thus, in this case, thefulcrum effect against the left side of the wellbore causes the bit tocreate a hole with a right hand bias.

[0106] The above operation whereby the wider side of the inner sleevecan be switched either to the right hand side or left hand side of thepregnant portion 20 of the housing is a simplified mode of operation.However, the device of the present invention is capable of far morecomplex operations. In the preferred embodiment, the position of thesleeve can be controlled to within a tolerance of 10° or less in somecases.

[0107] The wider side of the inner sleeve 12 can even be oriented 180°away from the pregnant portion 20. This arrangement places the fulcrumforce at two points of the assembly at the bottom of the outer housingand also on the bit itself This causes the bit to move downwards, butthe method of undercutting the outer housing. In a similar manner, thebit could also be driven upwards by aligning the wider part of the innersleeve along an axis which is parallel with the pregnant housing. Thiswould cause the bit to be driven upwards. Therefore, any combination ofup/down/left/right bit directional control could be accomplished.

[0108]FIG. 6 shows a further embodiment of the present invention. Toavoid unnecessary repetition, the same reference numerals have been usedas for FIG. 1. The construction of the mandrel II and the outer housing13 are identical to those described for FIG. 1. However, the upper partof the inner sleeve differs from that shown in FIG. 1 in that the upperpart of the inner sleeve 12 a is concentrically bored. This combinationof a concentric upper sleeve and an eccentric lower sleeve 12 b allowsmore control over the drilling direction, and has substantialarrangement with respect to the drilling mechanics. Further, thisrelatively simple arrangement whereby only movement of the upper sleeveis required is particularly advantageous. This so-called “point-the-bit”arrangement can also be achieved if the lower sleeve 12 b is concentricand the upper sleeve 12 a is eccentric.

[0109] The forces which are created in a “point-the-bit” scenario maydiffer from those utilised when two eccentric cams are provided. In aconfiguration comprising an eccentric cam and a concentric inner sleevesection, the net effect is to tilt the bit off the axis and thus givesome degree of tilt to the bit cutting structure. Such an arrangementwould give considerable advantages when drilling the wellbore and mayresult in a cleaner profile to the wellbore, a desirable state ofaffairs particularly when drilling extended reach well profiles.

[0110] If the concentric sleeve section is placed closer to the bit thanthe cam, the net effect of the cam section will be lower than that wherethe cam section is placed closer to the bit than the concentric sleeve.Therefore, to achieve the same degree of wellbore curvature from bothconfigurations, a larger offset cam would be required if the cam was atthe upper end of the tool.

[0111] The pregnant portion 20 of the outer housing 13 provides thereference point or “earthing point” against which the bit bias isreferenced, The actual bias forces are applied to the appropriate sideof the wellbore through one of the stabiliser shoes 21. In use, themandrel of the tool would be rotating. It is important that rotation ofthe mandrel 11 does not cause the outer housing 13 to rotate. Therefore,it is important that the rotational torque transferred to the outersleeve from the rotating mandrel 11 does not exceed the self-rightingtorque mass of the outer housing 13 due to gravity. If the outer housing13 turns away from the reference on the low side of the hole, the bitbias will not be correct and the directional qualities of the devicewill fail. Therefore, it may be necessary to use different speeds forrotating of the mandrel 11 in order to overcome the mass torquelimitations of the outer housing 13. Paradoxically, the mass of thehousing 13 becomes more effective as the angle of inclination (wellboredeviation from vertical) increases. Therefore, higher rotational speedsmay be used in this situation. Fortunately, this ability to use higherspeeds at larger angles of inclination is coincidental with therequirement for rapid tool response in high angle “near horizontal orhorizontal” wellbore. The operator will have to monitor the downholeperformance of the tool to determine if the tool is turning away fromthe low side reference point. Standard well survey devices can providethis information. Adjustments in rotational speed of the mandrel can bevaried at the surface to compensate for any shortfall in the mass-torquecapacity of the outer housing As previously discussed, in addition tothe operator wishing to drill in a specific direction, there is also avariable force which attempts to drive the bit away from the desiredtrajectory.

[0112] The prior art of deviation correction required a turn in thedirection of the wellbore in order to correct for drift left/right(azimuth) or up/down (inclination) from the required wellbore path.Essentially, a bent sub and downhole motor (or steerable motor) would beplaced in the wellbore and orientated in the required direction tocorrect for the calculated directional drifts These tools would place adogleg (a relatively sharp tun in the wellbore when compared to theoverall wellbore) at the point of correction. Once the wellbore wasestablished in the correct direction, standard drilling techniquesresume until the next survey shows unacceptable drift. Thus, a wellboreis not straight or smooth—it looks like a corkscrew. The instant devicewill allow for relatively smooth correction; thus, the wellbore will notlook like a corkscrew and will be easier to enter and exit during alldrilling, casing and production operations. That is, the “quality” ofthe wellbore will be significantly improved over the present state ofthe art

[0113] It should be noted that the inner eccentric sleeve can bemanufactured with varying degrees of eccentricity or offset from thewellbore center-axis. The required eccentricity would depend on theformation, the diameter of the wellbore, speed of drilling, type ofdrilling, maximum projected course alternation of the wellbore and thelike. The vector interaction of the shoe with the wellbore wall isselectively controlled by the rotation of the inner sleeve; thus, themagnitude of the offset force is dictated by the ratio of the innersleeve's eccentricity. A smaller ratio being equal to a smaller vectorforce and a larger ratio being equal to a larger vector force. Theoffset can vary from tenths of an inch [millimeters] up to inches[centimeters], and ideally, should be field replaceable and adjustable.The larger the offset, the sharper the change in wellbore direction andthe higher the load on the internal bearings. In drilling a straightwellbore the eccentricity offset should be less than about ½-inch [1.27cm].

[0114] It should also be remembered that the inner eccentric offset andthe effective gauge of the tool (effective gauge being defined as thetool diameter between the outer surfaces of the shoes, or the housingtouch point and the internal diameter of the wellbore) are interrelatedThus, it is important that the effective gauge of the tool be readilyadjustable in the field to fit the wellbore gauge (same as the tool'seffective gauge) or to account for some unexpected interaction with thetool. For example, the formation may be known to drive the tool fiber tothe right than required; thus, the right shoe could be increased inthickness while the left shoe could be decreased in thickness in orderto compensate for this trend. The overall effective gauge of the toolwould remain the same, bid the side wellbore force on the right of thewellbore would be effectively increased The actual values and the likewould have to be field determined, as are many parameters in thedrilling industry. Thus, the shoes are field replaceable and are held inplace by pins or any similar effective retaining mechanism.

[0115] The choice of inner sleeve and consequential offset, and thetool's effective gauge, may be made at the rig site. The drillingengineers would look at formation characteristics, the drilling programand other well known parameters to determine an initial offset andgauge. If the tool was over- or under-correcting, then the inner sleeve(or shoes) would be changed at a suitable opportunity (such as a “bittrip”) and the tool returned to the wellbore.

[0116] Previously, the specification has referred to drive means forpositioning the inner sleeve 12 with respect to the housing 13. FIGS. 7Aand 7B show potential arrangements for positioning the inner sleeve 12with respect to the outer housing.

[0117] In FIG. 7A, the driver is located within the pregnant portion ofthe housing 20. A cavity 27 is located within the pregnant portion 20.Within this cavity is located a drive gear 25. The outer circumferenceof the inner sleeve 12 is provided with a pinion gear. The teeth onpinion gear 25 are capable of inter-engaging with the teeth on rack 26such that movement of the pinion 25 effects movement of the sleeve 12with respect to the outer housing 13. Further, typically, the means fordriving pinion 25 which may comprise an electric, hydraulic motor orother means, will be located within the pregnant portion 20 of housing13. The power supply may be provided by a battery which is also locatedwithin the pregnant housing or, the rotation of the mandrel II may beused to rotate the pinion 25.

[0118]FIG. 7B shows a variation on the arrangement of FIG. 8A. Here, arack is provided around the inner circumference of the outer housing 13.The weighted side of inner sleeve 12 is provided with pinion 25.Movement of the pinion 25 effects movement of the outer housing 13 in asimilar manner to that which was described with reference to FIG. 7A.

[0119] As the teeth of the rack 26 and the pinion 25 interact, the innersleeve 12 and outer housing are locked in position with respect to oneanother once pinion 25 becomes stationary.

[0120] In order to change direction of the tool or the correct for bitwalk, the drive means must be actuated and told by how much to move theinner sleeve. Such information could be signaled from the surface.Further, it is preferable if there is some method of signaling thesurface to confirm the position of the inner sleeve 12.

[0121] It is be possible to use survey tools and track the wellboredirection and, whenever the direction is not correct, the device 10 maybe signaled from the surface to make the required alteration. Forexample, to rotate the bearing part of the inner sleeve from left toright or vice versa, or from up to down or vice versa to any degree ofrotation of the inner sleeve 12 or parts of sleeve with respect to theouter housing, at surface and then communicated to the downhole devicein order to effect a required rotation of the inner sleeve.

[0122] The degree of rotation of the inner sleeve during setting thedevice is contingent upon the initial position of the sleeve, and therequired resultant direction of the wellbore.

[0123] The preferred technique will be described for the motion of asingle part of the inner sleeve which is illustrated in FIGS. 8 and 9. Apassageway, 17, is bored in the rotating mandrel which allows somedrilling fluid to exit the bore via additional offset passages bored inthe inner sleeve, 16, and in the outer housing, 15. The passageway, 17,in the rotatable mandrel terminates in bit-jet/orifice, 19, combination.The bit-jet is capable of taking the pressure drop without damage. Agroove, 1 8, is cut in the outer surface of the inner eccentric sleeve12 which allows the drilling fluid to exit the bore even if thepassages, 15,16, are not aligned. When the passages, 15,16, are aligned,the rate of drilling fluid leaving the bore is higher than the rate whenthe passages are not aligned. Thus, a pressure difference signal wouldoccur at the surface whenever the inner sleeve is toggled or switchedfrom one position to another.

[0124] In the right-most position more fluid leaves the bore. In theleft-most position, less fluid leaves the bore. A pressure change willoccur at the ground surface because more or less fluid is bypassing thebit. Pressure changes are easily measured in the industry. If thepressure changes from high to low, then the eccentric is in theright-most position. If the pressure changes from low to high, then theeccentric is in the left-most position. The construction of labyrinthinepassageways based on the principle details above may enhance the abilityof the tool and allow multiple sleeve positions to be indicated at thesurface.

[0125] Other techniques could be used to signal the state of the innersleeve and such techniques are not outside the scope of this disclosure.For example, an encoding using a series of coded pulses could be used.Such pulses would be sent to the surface during motion of the innersleeve which may be decoded, using standard industry techniques, todisclose the resting position of the sleeve 12. It may be possible topass an electrical, or acoustic, or some other signal to a secondarytool or to instrumentation within the bottom hole assembly and have thattool pass the required information to the surface. The passing of codedinformation to the surface as a series of mud pulses or other telemetrydevices is well accepted and used in the industry.

[0126] In a similar manner, the passing of pressure pulses from thesurface to the tool may be used to signal the logic to toggle the stateof the inner sleeve 12. For example, the simplest and preferred togglingtechnique is to stop drilling for a period of time which exceeds thetime period to add a joint of drill pipe. During this period of time,the mud pressure would drop and the logic “sees” the event The logicstarts a timer and after the proper period of time the inner sleeve istold to toggle its state. Depending on the motor means the sleeve wouldtoggle or wait until fluid flow resumed in order to cape a drivingforce. This technique may be expanded to signal a stepper motor drivemeans to move to a given position, or to individually signal a BHAincorporating both up/down and left/right tools. Thus, any of thestandard mud signaling techniques could be used.

[0127] The logic used in connection with the tool of the invention canbe an integral part of the tool or located completely separatetherefrom. Furthermore, an energy source or power pack for supplying thelogic circuits can be located within the tool, as an attachment locatedin a separate sub, or completely remote therefrom.

[0128] Communication between the surface and the instant device may alsobe established through use of the rotation of the drill string. Thelogic means can include means for detecting drill string rotationwherein said drill string rotation contains encoded information which isunderstood and decoded by downhole mechanisms or instrumentation whichdetermine the radial position of said inner sleeve of the apparatus.

[0129] Also, the logic means may include means for detecting drillstring rotation and measuring a time period between rotation andnon-rotation of the drill string The measured time period can be used todetermine when said inner eccentric sleeve should be rotated withrespect to said outer housing. Thus, the apparatus may include a timingdevice.

[0130] In addition, the logic means may include a method and apparatusfor enabling the instant device to detect the rotation of the drillstring and quantify the rotational speed of the drill sting in such amanner as to be able to accurately quantify the rotational speed inorder to determine a numerical value which may be used in determiningsleeve position.

[0131] Such an arrangement is shown in FIG. 10. The device 10 comprisesa outer housing 13 with an eccentric bore. An inner sleeve 12 is locatedwithin said bore such that the outer housing 13 is rotatably coupledabout said inner sleeve 12. The inner sleeve 12 also has an eccentricbore which is configured to accommodate a rotating mandrel 11 such thatsaid inner sleeve 12 can rotate relative to both said outer housing 13and said mandrel 11.

[0132] A communications device comprising a magnet 4 is attached to saidrotating member 11. The magnet is located in a pocket on said rotatingmember 11. This specific embodiment uses the magnet as an emitter.However, it will be appreciated by those skilled in the art that themagnet could be replaced by any type of emitting sensor.

[0133] The outer housing 13 contain instrument barrels 6. The instrumentbarrels 6 are provided with sensing means. During drilling of the wellbore 2, the heavy portion of the outer housing seeks the low side of thewell bore and the position of the outer housing remains relatively fixedwith respect to the well bore. The mandrel 11 and magnet 4 rotaterelative to the outer housing 13. Lines of flux 5 radiate from themagnet 4 with sufficient magnitude to overcome the Earth's ambient fieldThe flux lines 5 extend radially beyond the instrument barrel 6 suchthat sensors within the instrument barrel 6 can detect the intensity ofthe emitted magnetic field.

[0134] When the magnet 4 is rotated such that it is closest to thesensors in the instrument barrel 6, the sensors detect a maximumamplitude in the magnetic field. In a similar manner, when the magnet 4is furthest from the instrument barrel 6, a minimum in the amplitude ofthe magnetic field will be detected. The field detected by He sensorsmay be sinusoidal if it is possible to sense the radiated magnetic fieldat all times when the mandrel 11 is rotating. In order to accomplishthis, at least a part and possibly the entire drill string mandrel willhave to be constructed from austenic type materials, or materials withsimilar non-magnetic properties.

[0135] However, as it is only necessary to measure the frequency ofrotation of the mandrel 11, it is adequate if the sensor is justconfigured to detect a maxima in the field when the magnet is at itsclosest to the sensor. In other words, the sensor just needs to detect aseries of pulses where each pulse is equivalent to one each rotation ofthe mandrel 11.

[0136] Thresholds may also be set which negate the effect of the Earth'smagnetic field and which serve as limit switches These limit switchesmay be employed as a means of logic control within the sensor array orwithin a logic control sub assembly.

[0137] A second instrument barrel 6 a is also shown. This may alsocontain magnetic sensors. The provisions of two magnetic sensors allowserrors to be more easily detected.

[0138] The sensor which isolated within the instrument barrel ispreferably situated in a stainless steel, or another magneticallytransparent pressure vessel such that the instrumentation is isolatedfrom the borehole pressure. The instrumentation barrel may comprises amagnetometer, or Hall effect device or the like for detecting themagnetic field.

[0139] Inevitably, there will be material between the magnetic sensor inthe instrument barrel 6 and the magnet 4 located on the rotating member.This intervening material should, as far as possible, be magneticallytransparent. In other words, the magnetic field should pass through thismaterial without becoming deflected or distorted. Materials whichexhibit these properties include austenic stainless steels and othernon-ferrous material.

[0140]FIG. 11 shows an embodiment of the present invention. AS in FIG.1, the downhole tool is connected to a drill bit and an adapter sub 4.In FIG. 11, the lower part of the mandrel 11 is connected to the drillbit 7 by adapter sub 6.

[0141] The upper adapter sub 4 allows the tool 10 to be connected tosurveying tools 5 and drill collars 8. The drill collars are attached todrill string 9. Additional stabilisers (not shown) will be added as perstandard drilling procedures. FIGS. 12A to 12B show a diagrammaticillustration of an arrangement of stabilisers used in a drillingoperation without showing the required collars, survey tools and subs.

[0142]FIG. 12A is a diagrammatic illustration of an arrangement ofstabilizers used in a drilling operation without showing requiredcollars, survey tools and subs. The instant device, 10, is followed by asecond string stabilizer, 23, and any additional stabilizers, 22, thatthe drilling program may require.

[0143] As previously explained, the tool can provide directional controlboth up and down and left to right For up/down control the offsetprovided by at least one of the parts of the direction control means isprovided either next to the weighted side of the housing or opposite theposition of the weighted side of the housing. FIG. 12B is a diagrammaticrepresentation of a device used to control up/down only. Here the bit,7, is followed by a near bit stabilizer, 24, with the up/down tool 10M,placed at distance “l” from the bit. This distance would range between15 feet [4.57 m] and 30 feet [9.14 m]. (the use of the British System ofunits is the standard of the drilling industry; hence, this descriptionuses the industry standard.)

[0144] The above description has largely concentrated on a device wherethe direction control means are provided by eccentric sleeves or cams.However, the present invention can also be realized by using linearactuators as part of the direction control means. Such linear actuatorscan be provided so as to bias said mandrel in the same manner as theaforementioned sleeves or cams.

[0145]FIG. 13 shows a cross-section of the apparatus configured withlinear actuators.

[0146] To avoid unnecessary repetition, where appropriate, likereference numerals will be used to denote like features. Comparing FIG.13 with the cross-sections of FIG. 7A and 7B, it can be seen that aweighted housing 13 is provided which surrounds mandrel 11. Mandrel 11is located within sleeve 12. Mandrel 11 is free to move within sleeve12. Sleeve 12 is connected to housing 13 via three linear actuators, 31,33 and 35. The three linear actuators 31, 33 and 35 are disposed in aplane about said mandrel and are offset from one another by 120°. Eachof the linear actuators is configured such that it can extend or contentas required.

[0147] In FIG. 13, linear actuator 35 is fully extended, linear actuator33 is filly contacted and linear actuator 31 is partially extended Inthis arrangement, the mandrel is biased towards the top left of thefigure in the same manner as the mandrel of FIG. 7A. The dotted linesindicate a different position where linear actuator 35 is contracted andactuator 33 is extended to bias the mandrel position over towards theright hand side of the housing 13.

[0148] Thus, the linear actuators can be used to bias the mandrel withrespect to the weighted housing 13 as required in order to change thedirection of drilling.

[0149]FIG. 14 is a schematic illustrating a preferred embodiment of adevice in accordance with the invention where the device firer comprisesa sensor.

[0150] To avoid unnecessary repetition, the same reference numerals willbe used as those of FIG. 1. In addition a sensor 37 is located on lowermandrel 11 c. The sensor may be located at other positions on thedevice.

[0151] The sensor may be a gamma ray sensor and may be configured tosend information to the surface such that the tool may be controlledfrom the surface or may be configured to analyse the signals which itcollects such that the device can use this information to select its ownpreferred drilling direction.

1. An apparatus for selectively controlling the direction of a well borecomprising: a mandrel rotatable about a rotation axis; a directioncontroller comprising at least two parts configured to apply a force tosaid mandrel with a component perpendicular to the said rotation axis; ahousing having an eccentric longitudinal bore forming a weighted sideand being configured to freely rotate under gravity; and a driver forselectively varying the angle of the force relative to the weighted sideof the housing about said rotation axis, the driver being configured tomove the two parts independently of one another,
 2. The apparatus ofclaim 1, wherein said direction controller is configured to provide aforce to said mandrel at a point either above or below a centre line ofsaid housing and said centre line is halfway along the length of thehousing in the direction of the rotation axis.
 3. The apparatus of claim1, wherein said at least two parts are configured to apply a null forceto said mandrel.
 4. The apparatus of claim 1, wherein the directioncontroller comprises a sleeve with an eccentric bore to receive saidmandrel, said driver being configured to selectively rotate said sleeveabout the rotation axis relative to the housing.
 5. The apparatus ofclaim 4, wherein said sleeve comprises a first part which has a sleevewith an eccentric bore and a second part which has a sleeve with aneccentric bore.
 6. The apparatus of claim 4, wherein said sleevecomprises a first part which has an eccentric bore and a second partwhich has a concentric bore, wherein the first and second parts arelocated on opposite sides of the centre line of the housing.
 7. Theapparatus of claim 5, wherein the drive means is configured to move atleast two parts of said sleeve independently of one another.
 8. Theapparatus of claim 7, wherein said two parts are configurable to providea null force on said mandrel.
 9. The apparatus of claim 4, wherein saidsleeve is at least partially located within said eccentric bore of saidhousing.
 10. The apparatus of claim 1, wherein the direction controllercomprises a plurality of cams.
 11. The apparatus of claim 11, wherein afirst part of the direction controller comprises a first cam and asecond part of the direction controller comprises a second cam, thedriver being configured to move the first and second cams independentlyrelative to one another.
 12. The apparatus of claim 11, wherein the camsare configurable so that the direction controller provides a null forceon said mandrel.
 13. The apparatus of claim 1, wherein a first part ofthe direction controller comprises a cam and a second part of thedirection controller means comprises a sleeve with a concentric bore.14. The apparatus of claim 1, wherein the direction controller comprisesat least one linear actuator for applying the force with a componentperpendicular to the rotation axis of the mandrel.
 15. The apparatus ofclaim 1, wherein a first part of the direction controller comprises afirst linear actuator and a second part of said direction controllercomprises a second linear actuator, the fist and second linear actuatorsbeing independently moveable.
 16. The apparatus of claim 15, wherein thelinear actuators are configurable to provide a null force on saidmandrel.
 17. An apparatus for selectively controlling the direction of awellbore, the apparatus comprising: a mandrel which is rotatably about arotation axis; a direction controller comprising at least one linearactuator configured to apply a force to said mandrel; a housing havingan eccentric longitudinal bore and being configured to freely rotateunder gravity; and a drive means for selectively varying the angle ofthe force relative to the weighted side of the housing about saidrotation axis.
 18. The apparatus of claim 1, further comprising aplurality of stabiliser shoes provided on the outside of said housing.19. The apparatus of claim 18, wherein the plurality of stabiliser shoesare circumferentially offset by a predetermined amount in relation tothe weight of said housing.
 20. The apparatus of claim 18, having twostabiliser shoes.
 21. The apparatus of claim 1, wherein the driver isconfigured to change the direction within a tolerance of at most 5°,more preferably at most 1°.
 22. The apparatus of claim 1, wherein thedriver comprises an hydraulic or electric motor or the like.
 23. Theapparatus of claim 1, further comprising logic means for determiningwhen the direction of the force applied by said direction controllershould be moved.
 24. The apparatus of claim 23, wherein said logic meanscomprises a sensor for sensing drilling parameters and decoding suchparameters to determine when the direction of the force applied by saiddirection controller should be changed.
 25. The apparatus of claim 23,wherein said logic means comprises a sensor for sensing well bore fluidflow pulses and decoding said pulses to determine when the direction ofthe force applied by said direction controller should be changed. 26.The apparatus of claim 23, wherein the logic means further comprisesmeans for decoding and commanding said driver to change the direction ofsaid force relative to the housing.
 27. The apparatus of claim 23,wherein said driver and said logic means are stored with said housing.28. The apparatus of claim 23, wherein said logic means are locatedwithin a tubular housing connected at least one of the mandrel,direction controller or housing.
 29. The apparatus of claim 23, furthercomprising an energy source for supplying power to the driver and/or thelogic means.
 30. The apparatus of claim 1, wherein the mandrel comprisesa longitudinal bore and said bore is capable of passing wellbore fluids.31. The apparatus of claim 1 further comprising signalling means forsignalling the direction of the force relative to the heavy side of thehousing.
 32. The apparatus of claim 24, wherein said mandrel isconnected to a drill string wherein said drilling parameters includedrill string rotation and said logic means includes means for detectingdrill string rotation wherein said drill string rotation determines whendirection of the force is changed with respect to said outer housing.33. The apparatus of claim 24, wherein said mandrel is connected to adrill string wherein said drilling parameters include drill stringrotation and said logic means includes means for detecting drill piperotation wherein said drill string rotation determines said radialposition of said apparatus.
 34. The apparatus of claim 24, wherein saidmandrel is connected to a drill string wherein said drilling parametersinclude drill pipe rotation and said logic means includes means fordetecting drill string rotation and determining a time period betweenrotation and non-rotation of the drill string wherein said time perioddetermines when the angle of said force should be changed with respectto the weighted side of said housing.
 35. The apparatus of claim 24,wherein said mandrel is connected to a drill string, wherein saiddrilling parameters include drill string rotation and said logic meansincludes means for detecting drill pipe rotation and determining a timeperiod between rotation and non-rotation of the drill string whereinsaid time period determines said radial position.
 36. The apparatus ofclaim 4, wherein said mandrel has an interior, said housing has anexterior, and said sleeve has a first axial position and a second axialposition with respect to said housing, and wherein said signalling meanscomprises a series of drilling fluid passageways extending generallyradially through said mandrel said sleeve and said housing such that,when said sleeve is in said first position, said series of drillingfluid passageways align with each other so as to allow drilling fluid toflow readily from said interior of the said mandrel to said exterior ofsaid housing accompanied by a relatively low pressure drop, and whensaid sleeve is in said second position, said drilling fluid passagewaysare in misalignment so as to restrict drilling fluid flow from saidinterior of said mandrel to said exterior of said housing accompanied byrelatively high pressure drop.
 37. The apparatus of claim 36, wherein abit-jet and orifice combination is positioned within said generallyradial passageway in said mandrel adjacent said sleeve.
 38. Theapparatus of claim 1, further comprising a sensor assembly for sensinginformation about said geological strata which is being drilled.
 39. Anapparatus for selectively controlling the direction of a well borecomprising: a mandrel rotatable about a rotation axis; a directioncontroller configured to apply a force to said mandrel wad a componentperpendicular to the said rotation axis; a housing having an eccentriclongitudinal bore forming a weighted side and being configured to freelyrotate under gravity a driver for selectively varying the angle of thedirection of force about said rotation axis; and a sensor assembly forsensing information about said geological strata which is being drilled.40. The apparatus of claim 39, wherein said sensor assembly comprises asensor for sensing said information and an analyser for analysing datafrom said sensor, wherein said analyser is located at said mandrel,housing and direction controller combination.
 41. The apparatus of claim40, wherein said sensor is configured to sense gamma rays.
 42. Theapparatus of claim 39, wherein said drive means controls the angle ofthe direction of the force on the basis of the sensed geological data.43. An apparatus for drilling a well bore, the apparatus comprising: adrilling member configured to drill in a predetermined drillingdirection; direction controller for controlling the drilling directionof said drilling member; a sensor for determining at least acharacteristic of the strata being drilled; wherein said directioncontroller determines the drilling direction based on the data collectedby said sensor.
 44. The apparatus of claim 43, wherein said directioncontroller is located with said drilling member, such that said drillingmember can determine a preferential drilling direction based on datafrom said sensor.
 45. The apparatus of claim 43, wherein at least a partof said direction controller means is remote from said drilling member.46. The apparatus according to claim 43, wherein said drilling membercomprises an apparatus according to claim
 1. 47. The apparatus of claim1, wherein said driver comprises a drive wheel and a track, said drivewheel being engagable with said track such that movement of said drivewheel causes movement of said track relative to said drive wheel andsaid drive wheel when stationary prevents movement between said trackand drive wheel, the drive wheel and track being located such thatmovement of the drive wheel effects relative movement between the forceand the weighted side of the housing.
 48. The apparatus of claim 47,wherein said track is located on a surface of said housing and saiddrive wheel is mechanically connected to said direction controller. 49.The apparatus of claim 47, wherein the track is located on an innersurface of said housing.
 50. The apparatus of claim 47, wherein saidtrack is located on a surface of said direction control means and saiddrive wheel is mechanically connected to said housing.
 51. The apparatusof claim 50, wherein the track is located on an outer surface of saiddirection control means.
 52. The apparatus of claim 47, wherein saiddrive wheel comprises a plurality of teeth about its edge, and saidtrack comprises a plurality of teeth which are configured to interlockwith the teeth of said drive wheel to effect relative movementtherebetween.
 53. The apparatus of claim 47, wherein the direction ofthe force is changed by a predetermined angle in response to rotation ofsaid drive wheel through a predetermined rotation angle.